Two-Piece Plunger with Sleeve and Spear for Plunger Lift System

ABSTRACT

A plunger lift system has a plunger with a sleeve and a spear that dispose in tubing. The sleeve and spear can move in the tubing between a bumper and a lubricator. The sleeve has a passage for fluid to pass therethrough, and the spear can insert partially into the sleeve&#39;s passage. The sleeve and spear fall independently of one another from the surface to the bumper. When disposed on the bumper, the sleeve and spear mate together. Building gas pressure downhole can then lift the mated sleeve and spear, which can sweep liquid along the tubing and push the liquid along with them to the surface.

BACKGROUND

Liquid buildup can occur in aging production wells and can reduce thewell's productivity. To handle the buildup, operators can use beam liftpumps or other remedial techniques, such as venting or “blowing down”the well. Unfortunately, these techniques can cause gas losses.Moreover, blowing down the well can produce undesirable methaneemissions.

In contrast to these techniques, operators can use a plunger liftsystem, which can de-liquefy a gas well, reduce gas losses, and improvewell productivity. The plunger lift system can use one of two types ofplungers: a conventional plunger and a continuous (bypass) plunger. Theconventional plunger is typically used to lift built-up fluid at thedownhole end of the tubing string.

A continuous plunger is typically used when the well is still flowing atvery high flow rates, above critical velocity, during early interventionof the well. To do this, the continuous plunger is designed to fallagainst the flow of the well and uses a valve on the plunger, such as aninternal shifting rod. When the plunger lands downhole on the bumper,the valve is closed. Then, when built-up pressure lifts it in thetubing, the continuous plunger is primarily used to sweep accumulatedfluids along the tubing wall.

For example, a plunger lift system 10 of the prior art is shown in FIG.1A. In the system 10, a plunger 50A is disposed in production tubing 16,which is deployed in casing 14 from a wellhead 12. During operation, theplunger 50A moves between a lubricator 30 at the surface and a landingbumper 20 downhole.

The plunger 50A shown in FIGS. 1A-1B is a two-piece plunger of thecontinuous type. By contrast, a conventional plunger 50B as shown inFIG. 2 has a single body that may be solid or semi-hollow and that hasexternal ribbing or the like for creating a pressure differential. Thecontinuous plunger 50B as in FIG. 2 is used when liquid build-up hasbecome an issue in part because the well is not flowing above criticalvelocity. The two-piece plunger 50A of FIGS. 1A-1B, however, can be usedin a well that is still flowing above critical velocity and liquidbuild-up has not become a significant issue yet.

The two-piece plunger 50A of FIGS. 1A-1B allows both pieces to fallfaster downhole than would be possible for such a solid or semi-hollowplunger 50B of the prior art. As best shown in FIG. 1B, the two-pieceplunger 50A has a separate sleeve 60 and ball 70. The sleeve 60 has aninner bore 62 that defines a seat 68. The ball 70 can fit against theseat 68 and can seal fluid flow up through the plunger's bore 62 duringoperation. The sleeve's outer surface can have ribbing 64 or the likefor creating a pressure differential. Particular examples of this typeof two-piece plunger 50A and its use are disclosed in U.S. Pat. No.6,467,541 and U.S. Pat. No. 6,719,060.

When used in the system 10 of FIG. 1A-1B, the sleeve 60 and ball 70dispose separately in the tubing 16. The ball 70 drops first to landnear the bottom of the well. The ball 70 falls into any liquid near thebottom of the well and contacts the bumper 20. The sleeve 60 drops afterthe ball 70 so it can fall to the bumper 20 as well. Thus, duringoperations, the ball 70 falls in the well first followed by the sleeve60 against high flow rates. They travel independently of each other.When they reach the bottom of the well, they unite and can then travelback to the surface to de-liquefy the well.

When the sleeve 60 reaches the ball 70, for example, they unite into asingle component. With the plunger 50A deployed to handle liquidbuildup, operators set the well in operation. Gas from the formationenters through casing perforations 18 and travels up the productiontubing 16 to the surface, where it is produced through lines 32/34 atthe lubricator 30. Liquids may accumulate in the well and can createback pressure that can slow gas production through the lines 32/34.Using sensors and the like, a controller 36 operates a valve 38 at thelubricator 30 to regulate the buildup of pressure in the tubing 16.Sensing the slowing of gas production due to liquid accumulation, thecontroller 36 shuts-in the well to increase pressure in the well.

As high-pressure gas accumulates, the well reaches a sufficient volumeof gas and pressure. Eventually, the gas pressure buildup pushes againstthe combined sleeve 60 and ball 70 and lifts them together to thelubricator 30 at the surface. The column of liquid accumulated above theplunger 50A likewise moves up the tubing 16 to the surface so that theliquid load can be removed from the well.

In this way, the plunger 50 essentially acts as a piston between liquidand gas in the tubing 16. Gas entering the production string 16 from theformation through the casing perforations 18 acts against the bottom ofthe plunger 50A (mated sleeve and ball 60/70) and tends to push theplunger 50A uphole. At the same time, any liquid above the plunger 50Awill be forced uphole to the surface by the plunger 50A.

As the plunger 50A rises, for example, the controller 36 allows gas andaccumulated liquids above the plunger 50A to flow through lines 32/34.Eventually, the plunger 50A reaches a catcher 40 on the lubricator 30and a spring (not shown) absorbs the upward movement. The catcher 40captures the plunger's sleeve 60 when it arrives, and the gas thatlifted the plunger 50A flows through the lower line 32 to the salesline. A decoupler or striker rod (not shown) inside the lubricator 30can separate the ball 70 from the sleeve 60. The ball 70 can thenimmediately fall toward the bottom of the well. In the meantime, thecatcher 40 holds the sleeve 60 and then releases the sleeve 60 after theball 70 is already on its way down the tubing 16.

Dropped in this manner, the sleeve 60 and ball 70 fall independentlyinside the production tubing 16. The sleeve 60 with its central passage62 can have gas flow through it as the sleeve 60 falls in the well. Onthe other hand, flow travels around the outside of the ball 70 as theball 70 falls in the well. Unfortunately, the ball 70 tends to fallslower than the sleeve 60. In fact, the ball 70 can knock about againstthe tubing 16 when falling through high gas flow.

Therefore, the system 10 must properly time the dropping of the ball 70and sleeve 60 so that the ball 70 has sufficient time to fall downholebefore the sleeve 60 is allowed to fall. Solutions for decoupling theball 70 and for timing the dropping of the ball 70 and the sleeve 60 aredisclosed in U.S. Pat. No. 6,467,541 and U.S. Pat. No. 6,719,060, forexample. Although such schemes may be effective, what is needed is amore robust approach with less complexity.

Other two piece plunger designs are disclosed in U.S. Pat. No.6,148,923; U.S. Pat. No. 6,209,637; U.S. Pat. No. 7,383,878; and U.S.Pat. No. 8,485,263. For example, the two-piece plunger as disclosed inU.S. Pat. No. 6,209,637 has an upper sleeve and a lower mandrel. Theupper sleeve has a tubular body with a central passage. The lowermandrel is a body with a robust lower end, two centralizer sections withoutward extending arms, a circular plate with slots, and a pin at thetop. The pin is shorter than the sleeve and nests therein with a sealingmember. In a similar configuration, the two-piece plunger as disclosedin U.S. Pat. No. 7,383,878 has an upper sleeve and a fluted lowermandrel. A short head at the top of the mandrel latches in the sleeve.

In another example, the two-piece plunger as disclosed in U.S. Pat. No.8,485,263 is reproduced in FIGS. 3A-3B. This plunger 50C is amulti-sleeve plunger having a main sleeve 80 and an ancillary sleeve 90that can mate and unmate during operations. The main sleeve 80 has acylindrical body with an internal passage 82 through which flow can passas the sleeve 80 falls in the well. Similarly, the ancillary sleeve 90also has a cylindrical body with an internal passage 92 through whichflow can pass as the sleeve 90 falls in the well.

Turning to the main sleeve 80, the exterior of the main sleeve 80 canhave ribbing 81 or other features for creating a pressure differentialacross the sleeve 80 when disposed in tubing. The sleeve's internalpassage 82 can define a fish neck or other profile 86 allowing forretrieval of the sleeve 80 if needed. At its distal end, the main sleeve80 defines a narrow stem 84 on which the ancillary sleeve 90 can fitwhen mated thereto. The distal end of this narrow stem 84 has a nodule85 and defines ports 88 communicating with the sleeve's internal passage82. These ports 88 allow flow through the main sleeve's internal passage82 as it falls in the well.

Turning to the ancillary sleeve 90, its internal passage 92 can alsohave a fish neck profile 96 for retrieval. The uphole end of theancillary sleeve 90 is open to fit onto the main sleeve's narrow stem84. The lower end of the ancillary sleeve 90, however, is closed exceptfor an orifice 95 through which the nodule 85 of the main sleeve 80 canfit when mated thereto.

The two sleeves 80/90 when uncombined can allow fluid to pass throughtheir passages 82/92 as they fall down the tubing. When landed on thebumper downhole, the two sleeves 80/90 can combine or mate with oneanother to close off fluid flow therethrough. When combined, theancillary sleeve 90 covers the slots 88 in the main sleeve's stem 84,and the stem's nodule 85 closes off the ancillary sleeve's orifice 95.The sleeves 80/90 remain mated together while disposed on the bumper andwhen pressure lifts the sleeves 80/90 and liquid column to the surface.

As the above examples show, there are several ways to implement aplunger lift system. However, operators are continually striving todevelop more efficient and effective plunger lift systems to increasethe production from a gas well. Systems in the prior art may requirelonger cycle times for the plunger to fall, for pressure to build-up,and for liquid to then be lifted. The well may need to be shut in forlonger periods than desired, and reduced amounts of gas may be producedover time as a result.

The subject matter of the present disclosure is directed to overcoming,or at least reducing the effects of, one or more of the problems setforth above.

SUMMARY

In one arrangement, a plunger lift apparatus for tubing in a well has asleeve and a spear. The sleeve for disposing in the tubing defines apassage therethrough from a first proximal end to a first distal end.The spear for disposing in the tubing downhole of the sleeve iselongated, extending from a second proximal end to a second distal end.The spear's second distal end is longer than its second proximal end.The second distal end of the spear inserts in the passage of the sleeve,and the second proximal end of the spear mates with the first proximalend of the sleeve. The spear at least partially closes fluidcommunication through the passage of the sleeve when mated therewith.

In another arrangement, a plunger lift apparatus for tubing in a wellhas a sleeve and a spear. The sleeve for disposing in the tubing definesa passage therethrough. The spear for disposing in the tubing downholeof the sleeve mates with the sleeve downhole and at least partiallycloses fluid communication through the passage of the sleeve when matedtherewith. In some arrangements, the spear deploys at a faster ratedownhole in the tubing than the sleeve.

In yet another arrangement, a plunger lift apparatus for tubing in awell has a sleeve and a spear. The sleeve for disposing in the tubingdefines a passage therethrough and has a first ratio of cross-sectionalarea to weight. The spear for disposing in the tubing downhole of thesleeve mates with the sleeve downhole and at least partially closesfluid communication through the passage of the sleeve when matedtherewith. The spear has a second ratio of cross-sectional area toweight ratio being less than the first ratio of the sleeve.

In the various arrangements, the sleeve and the spear mated togethermove uphole within the tubing by application of a pressure differential.To facilitate this, the sleeve can have means for producing a pressuredifferential across the sleeve by using a contoured surface, ribs,brushes, pads, etc.

A catcher disposed uphole of the tubing can be operable to engage thesleeve when reaching the surface, and a controller operably coupled tothe catcher can control engagement of the catcher with the sleeve.Additionally, the controller can operate a valve in fluid communicationwith the tubing based on a condition in the tubing.

As noted above, the spear can deploy at a faster rate downhole in thetubing than the sleeve, although other arrangements are possible.Overall, the spear has a first weight greater than a second weight ofthe sleeve, has a first cross-sectional area that is greater than asecond cross-sectional area of the sleeve, and has a first axial lengthgreater than a second axial length of the sleeve. More particularly, thespear has a first ratio of cross-sectional area to weight that is lessthan a second ratio of cross-sectional area to weight of the sleeve.

To close off fluid communication when mated, the sleeve can define aseat in the passage toward the first proximal end. The seat can beconfigured to engage a portion of the second proximal end of the spearin a metal-to-metal seal, although other types of sealing arrangementscan be used.

The second proximal end of the spear can include a head with a firstouter dimension, while the second distal end of the spear can include astem extending from the head and having a second outer dimension lessthan the head. The head can further define a bullet tip, while the stemcan define a sharpened end. To stabilize engagement of the spear on abumper downhole in the tubing, the head can have one or more landersdisposed thereon.

In a plunger lift method for tubing in a well, the spear is deployeddownhole in the tubing. The sleeve is deployed downhole in the tubingseparate to the spear and allows fluid communication through the passagein the sleeve. Fluid communication is prevented through the passage insleeve by inserting a distal end of the spear in the passage and matinga proximal end of the spear with the passage. Application of a pressuredifferential can then lift the mated sleeve and spear uphole in thetubing.

The method can involve catching the sleeve lifted uphole in the tubingand redeploying the sleeve downhole in the tubing by releasing thesleeve manually or automatically. The spear can be redeployed downholein the tubing by unmating the spear from the sleeve lifted uphole in thetubing and permitting the spear to deploy downhole in the tubing beforepermitting the sleeve to deploy downhole.

Deploying the spear downhole in the tubing can involve permitting thespear to deploy at a faster rate downhole than the sleeve, althoughother arrangements are possible. Overall, the spear can be provided witha first weight greater than a second weight than the sleeve, with afirst cross-sectional area that is greater than a second cross-sectionalarea of the sleeve, and with a first axial length greater than a secondaxial length of the sleeve. More particularly, to permit the spear todeploy at the faster rate downhole than the sleeve, the spear can beprovided with a first ratio of cross-sectional area to weight that isless than a second ratio of cross-sectional area to weight of thesleeve.

The foregoing summary is not intended to summarize each potentialembodiment or every aspect of the present disclosure.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1A illustrates a plunger lift system according to the prior art.

FIG. 1B illustrates a partial cross-section of a two piece plungeraccording to the prior art.

FIG. 2 illustrates a partial cross-section of a conventional plungeraccording to the prior art.

FIGS. 3A-3B show side and cross-sectional views of a multi-sleeveplunger according to the prior art.

FIGS. 4A-4B illustrate a plunger lift system having a two-piece plungeraccording to the present disclosure during stages of operation.

FIGS. 5A-5B respectively illustrate a perspective view and across-sectional view of a sleeve and a spear of the disclosed plungercoupled together.

FIG. 6A illustrates a cross-sectional view of the sleeve of thedisclosed plunger.

FIG. 6B illustrates a cross-sectional view of the spear of the disclosedplunger.

FIGS. 7A-7D illustrate cross-sectional views of various configurationsof the disclosed plunger.

FIGS. 8A-8B illustrate a perspective view and an end view of thedisclosed plunger having landers.

FIG. 9 illustrates a detail of a fishneck profile on the sleeve of thedisclosed plunger.

DETAILED DESCRIPTION

A gas well in FIGS. 4A-4B has a plunger lift system 10 to handle theaccumulation of formation liquid in the well. In an earlier stage of thewell's productive life, a sufficient amount of gas may have beenproduced to deliver the formation liquids to the surface. However, dueto the age of the well or other factors, the plunger lift system 10 mayneed to handle issues with liquid buildup in the well. In general, theplunger lift system 10 can lift oil, condensate, or water from thebottom of the well to the surface.

As shown, the well has production tubing 16 disposed in casing 14, whichextend from a wellhead (not shown). Formation fluids enter the casing 14via casing perforations 18. The produced fluids then enter theproduction tubing 16 and bypass a bottomhole bumper 20 positioneddownhole. At the wellhead, a lubricator 30 routes produced fluids to asales line.

A two-piece plunger 100 disposes in the tubing 16 and can move betweenthe bumper 20 and the lubricator 30 to lift accumulated liquid to thesurface. As shown briefly in FIGS. 4A-4B, the plunger 100 has a sleeve110 and a separate spear 150. Being two pieces, the sleeve 110 and spear150 are separate components that are disposed independently in thetubing. However, during aspects of operation, these two components110/150 can fit together to complete the plunger 100. (Further detailsof the plunger 100 are provided later.)

Initially, the plunger 100 rests on the bottomhole bumper 20 toward thebase of the well. When disposed at the bumper 20, the two components110/150 mate together. As gas is produced through lines 32/34 on thelubricator 30, liquids may accumulate in the wellbore and createback-pressure that can slow gas production. Using sensors and the like,a controller 36 operates a valve 38 at the lubricator 30 to regulate thebuildup of gas in the tubing 16. Sensing the slowing of gas production,the controller 36 shuts-in the well to increase pressure in the well ashigh-pressure gas begins to accumulate.

When sufficient gas volume and pressure level are reached, the gaspushes against the plunger 100 and eventually pushes the plunger 100upward from the bumper 20 toward the lubricator 30 as illustrated inFIG. 4A. The column of liquid above the moving plunger 100 likewisemoves up the tubing 16 so the liquid load can eventually be removed fromthe well at the surface. In this way, the plunger 100 essentially actsas a piston between liquid and gas in the tubing 16.

As the plunger 100 rises, the controller 36 allows gas and accumulatedliquids above the plunger 100 to flow through the outlets 32/34.Eventually, the plunger 100 reaches the lubricator 30, and a spring 42absorbs the plunger's impact. A catcher 40 on the lubricator 40 can thencapture the plunger's sleeve 110 if desired. The spear 150 may be struckoff from the sleeve 110 using a decoupler or striker rod (not shown) atthe lubricator 30, or the spear 150 may simply be free to decouple onits own from the sleeve 110 in the absence of sufficient gas flow.

Meanwhile, the gas that lifted the plunger 100 flows through the loweroutlet 32 to the sales line. Once the gas flow stabilizes, thecontroller 36 can shut-in the well and releases the sleeve 110, whichdrops back downhole to the bumper 20. Ultimately, the cycle can repeatitself.

As noted, the catcher 40 can hold the sleeve 110 and can control therelease of the sleeve 110 to fall downhole after the spear 150. Yet, insome circumstances, using the catcher 40 to hold the sleeve 110 may notbe required during a lift cycle. Instead, the sleeve 110 can be held inthe lubricator 30 by the immediate uphole flow of gas during the liftcycle. This may occur for a sufficient amount of time after the spear150 has descended into the well.

For its part, the spear 150 as shown in FIG. 4B is free to drop off thesleeve 110 when pressure fails to support it thereon. Thus, the spear150 can promptly fall off the sleeve 110 and toward the bottom of thewell when gas flow cannot support it coupled to the sleeve 110.Accordingly, a particular decoupler or striker rod may not be needed forthis implementation to decouple the spear 150.

In general, the catcher 40 can have a conventional design when used. Asshown in FIG. 4A, for example, the catcher 40 has a biased ball 44 thatcan latch onto the sleeve 110 and hold it. For example, the ball 44 canengage in grooves or detents of the sleeve's ribbing or in some othersuitable profile or shoulder. In one implementation, the catcher 40 canbe manually operated. As such, the catcher 40 can catch the sleeve 110in the lubricator 30 so the sleeve 110 can be released manually by handor can be retrieved and inspected as needed.

Alternatively, the catcher 40 can be automated. In such an auto catchassembly, the catcher 40 can automatically catch the plunger's sleeve110 when it arrives at the surface during a lift cycle. A sensor (notshown) can be used to detect the plunger's arrival if necessary.

The controller 36 can then indicate when the sleeve 110 is to tripdownhole rather than allowing the sleeve 110 to drop when the flow ratemomentarily decreases. For such an automated catcher 40, a spring andpiston arrangement 46 can bias a ball 44 on the catcher 40 usingcompressed gas from a source controlled by the controller 36. Thepressure can be applied to a spring and piston arrangement 46 usingdiaphragm top works (not shown) or other device. With pressure applied,the ball 44 forces into the lubricator's pathway so the ball 44 canengage the plunge's sleeve 110. When appropriate, the controller 36 canthen release gas pressure from the spring and piston arrangement 46. Atthis point, the weight of the sleeve 110 can push the ball 44 out of theway so the sleeve 110 is free to fall into the well.

The spear 150 drops first into the well either because it is not held bythe catcher 40 (if present) and is free to fall with less restriction.In an alternative arrangement noted previously, a striker rod at thelubricator 30 could be used to dislodge the spear 150 using techniquesknown in the art. Once the spear 150 drops, the sleeve 110 follows indue course so the components 110/150 fall separately and independentlyof one another down the tubing 16. This enables the plunger 100 to fallfaster downhole and with less restriction than other types of plungers.Once they reach bottom of the well, they unite and can eventually belifted up to the surface to de-liquefy the gas well.

Because the spear 150 may fall promptly, it may fall while the well isstill flowing. Thus, the spear 150 has a streamlined configurationallowing it to fall through higher flow rates. In particular, the spear150 is elongated and has the form of a rod or stem with weighted bulletor head at its downhole end. With this configuration, the spear 150 canavoid issues encountered by dropped balls or the like and may be able toavoid friction issues and other problems when falling against flow.Nevertheless, the spear 150 is preferably designed to fall faster thanthe sleeve 110, although other arrangements are possible. Therefore,timing the dropping of the two components 110/150 may not be as much ofan issue in the plunger lift system's operation as found in othersystems.

When the separate components 110/150 reach the bottom of the well, theynest together in preparation for moving upwardly once pressure buildsup. For example, the spear 150 falls into any liquid near the bottom andlands on the bumper 20. The sleeve 110 drops after the spear 150 to thebumper 20. When the sleeve 110 reaches the spear 150, they unite into asingle component. Any gas entering the tubing 16 from the formation thenstarts to act against the bottom of the mated component 110/150 and cantend to push them together uphole. In this way, any new liquid above themated components 110/150 can be forced uphole to the surface.

FIGS. 5A-5B respectively illustrate a perspective view and across-sectional view of the sleeve 110 and spear 150 of the disclosedplunger 100 coupled together. FIG. 6A illustrates a cross-sectional viewof the sleeve 110 of the disclosed plunger 100 showing variousdimensions, and FIG. 6B illustrates a cross-sectional view of the spear150 of the disclosed plunger 100 showing various dimensions.

The sleeve 110 of the plunger 100 has a cylindrical body with anexternal surface 120 and defines a central passage 112 from a proximalend 114 to a distal end 116. (In context, the proximal end 114 is thedownhole end oriented downhole from the midpoint, middle, center, etc.of the sleeve 110, while the distal end 116 is the uphole end orienteduphole of the sleeve's midpoint.) The exterior of the sleeve 110 canhave ribbing 120 for creating a pressure differential across the sleeve110 when disposed in tubing. The ribbing 120 may be of any suitabletype, including wire windings or a series of grooves or indentations.The ribbing 120 creates a turbulent zone between the sleeve 110 and theinside of the producing tubing, which restricts liquid flow on theoutside of the sleeve 110. The ribbing 120 can also be used as a catcharea for holding the sleeve 110 at the wellhead.

Although the sleeve's exterior is shown having ribbing 120, otherfeatures can be used to create a pressure differential across the sleeve110 when disposed in tubing. For example, the sleeve 110 can have fixedbrushes, biased T-pads, or other known components for creating thepressure differential.

The spear 150 of the plunger 100 also has a proximal end 152 and adistal end 154. (In context, the proximal end 152 is the downhole endoriented downhole from the midpoint, middle, center, etc. of the spear150, while the distal end 154 is the uphole end oriented uphole of thespear's midpoint.) As already noted, the spear 150 is elongated,including a bullet or head at the proximal end 152 and including a rodor stem 154 extending from the head 152 along the length of the spear150 to the distal end 154. Contrary to the exterior of the sleeve 110,the spear 150 has a smooth exterior surface. The head 152 has a bulletcontour 153 to facilitate its passage downhole through gas flow in thetubing. The very tip of the head 152 may be flattened where the head 152engages the components of the downhole bumper (not shown).

When the sleeve 110 and spear 150 are coupled together, the stem 154 ofthe spear 140 at least partially installs in the passage 112 of thesleeve 110. (In fact, the stem 154 with its smaller outer dimension cansubstantially fit inside the sleeve's passage 112 so that the stem 154extends at least three-fourths of the length or more of the sleeve'spassage 112.) The head 152 of the spear 150, which may encompass aboutone-third or less of the length of the spear 150, at least partiallymates with the proximal end 114 of the sleeve 110, and the spear 150 atleast partially closes fluid communication through the passage 112 ofthe sleeve 110 when mated therewith.

In particular, the passage 112 of the sleeve 110 defines a seat orrestriction 118 toward the sleeve's proximal end 114. The head 152 ofthe spear 150 defines a transition 158 from a larger diameter (D5) to anarrower diameter (D4) of the stem 154. A sharpened end 155 of the stem154 at the distal (uphole) end of the spear 150 can facilitate insertionof the stem 154 into the passage 112. When the stem 154 inserts insidethe sleeve's passage 112, the transition 158 mates with the seat 118 toclose off fluid flow through the passage 112. As shown here, thetransition 158 is preferably smooth and contoured in accordance with therest of the spear 150. This is not strictly necessary since a sharpertransition or shoulder could be used.

As will be appreciated, the surface areas of the components 110/150against which flow acts, the weight of the components 110/150, theirdiameters, and other variables can be designed for a particularimplementation and can depend on several factors, such as the size ofthe production tubing, expected gas flow, formation fluid properties,etc. Some exemplary dimensions are provided here for illustrativepurposes.

When used for 2⅜-in tubing that can have an internal dimension of about1.995-in, the overall length (L1) of the sleeve 110 can be 6-in, and theoverall diameter (D1) of the sleeve 110 can be 1.9-in. The insidediameter (D2) of the bore 112 can be about 1.5-in., and the bore's seat118 can have an inside diameter (D3) of about 1.2-in.

The overall length (L2) of the spear 150 can be 6.5-in. As will beappreciated, the spear's length (L2) as compared to the diameter of thetubing is sufficient that the spear 150 does not flip over, rotateend-to-end, or lodge during passage along the tubing. The overalldiameter (D4) of the spear's rod 154 can be 1.0-in, while the diameterof the head 152 can be 1.2-in at its maximum. The rod 154 can encompassabout 4.3-in of the spear's length, while the head 152 can make up theremainder of about 2.2-in. When the head 152 seats against the seat 118of the sleeve's bore 112, the engagement can be made roughly at about1.35-in. in diameter.

With these dimensions and with a standard steel density of about0.283-lb/in³, the spear 150 has a weight of about 1.65-lbs, whereas thesleeve 110 has a weight of about 1.61-lbs. The cross-sectional area ofthe sleeve 110 is about 1.404-in², while the cross-sectional area of thespear 150 is about 1.431-in². (Cross-sectional area as discussed hereinrefers to the area responsible for generating force under pressure.)Thus, the ratio of the cross-section area to the weight for the sleeve110 is higher than that of the spear 150. In the current example, thesleeve 110 has an area-to-weight ratio of about 0.872-in²/lb, and thespear 150 has a ratio of about 0.867-in²/lb. This makes the sleeve'sratio about 0.5% greater than the spear 150.

As will be appreciated, the above dimensions, weights, ratios, and thelike can be scaled for other implementations with different tubingsizes, such as 2 1/16, 2⅞, and 3½-in. Similarly, the above dimensions,weights, ratios, and the like can be adjusted accordingly to accommodateflow rates, fluid content, and other factors of a well.

In this regard, the overall length of the sleeve 110 and spear 150 canbe adjusted either alone or together to alter the weight, ratios, anddimensions of the plunger 100 for a particular implementation. In thisway, even for a given tubing size (e.g., the 2⅜-in discussed above), thelengths of the sleeve 110 and spear 150 can be adjusted to producedesired weights and ratios to meet the needs of the particular well,flow rates, and other variables encountered.

For example, FIGS. 7A-7D show various configurations of the plunger100A-D. FIGS. 7A-7D show the plunger 100A-D with longer designs comparedto the previous plunger of FIG. 5B. The plunger 100A in FIG. 7A has thesleeve 110 extending 8-in. and has the spear 150 extending about 9.2-in.The radial dimensions and cross-sectional areas of the sleeve 110 andspear 150 can be relatively the same as before due to the comparabletubing size, and the same materials can be used. The different overalllengths of the sleeve 110 and spear 150, however, alter the weight ofthese components. Here, the sleeve 110 can weigh about 2.06-Ib, whilethe spear 150 can weigh about 2.32-lb. Thus, the area-to-weight ratiofor the sleeve 110 can be 0.682-in²/lb and can be 0.617-in²/lb for thespear 150. This makes the sleeve's ratio 10.5% greater than the spear150.

As shown in FIG. 7B, the plunger 100B is shown in an even longer designwith the sleeve 110 extending 10-in. and the spear 150 extending about11.2-in. The radial dimensions and cross-sectional areas of the sleeve110 and spear 150 can be relatively the same as before due to thecomparable tubing size, and the same materials can be used. Here, thesleeve 110 can weigh about 2.54-Ib, while the spear 150 can weigh about2.76-lb. Thus, the area-to-weight ratio for the sleeve 110 can be0.553-in²/lb and can be 0.518-in²/lb for the spear 150. This makes thesleeve's ratio 6.7% greater than the spear 150.

As shown in FIG. 7C, the plunger 100C is shown in an even longer designwith the sleeve 110 extending 12-in. and the spear 150 extending about13.2-in. The radial dimensions and cross-sectional areas of the sleeve110 and spear 150 can be relatively the same as before due to thecomparable tubing size, and the same materials can be used. Here, thesleeve 110 can weigh about 3.0-Ib, while the spear 150 can weigh about3.2-lb. Thus, the area-to-weight ratio for the sleeve 110 can be0.468-in²/lb and can be 0.447-in²/lb for the spear 150. This makes thesleeve's ratio 4.7% greater than the spear 150.

As shown in FIG. 7D, the plunger 100D has the spear 150 extending agreater length through the sleeve 110. Here, the proximal end 152 of thespear 150 extends beyond the proximal end 114 of the sleeve 110, and thedistal end 154 of the spear 150 extends beyond the distal end 116 of thesleeve 110. In one advantage when the combined sleeve 110 and spear 150arrives at top of the lubricator (30), the distal end 154 of theelongated spear 150 engages a strike pad of the lubricator (30). Thisknocks the spear 150 free of the sleeve 110 so the spear 150 can startits downward journey. This arrangement of the longer spear 150 can beused with any of the various sizes and configurations of the plunger 100disclosed herein. As shown in this embodiment and as is possible inothers, the distal end 154 of the spear 150 can further include afishneck head or the like to assist with potential retrieval ifnecessary.

As shown in FIGS. 7A-7D, the stem 154 can substantially fit inside thesleeve's passage 112 so that the stem 154 extends almost the entirelength of the sleeve's passage 112. As also shown, the spear's head 152may encompass about one-quarter, one-fifth, or less of the length of thespear 150. Thus, when the spear 150 mates with the sleeve 110, the stem154 mostly completes the sleeve's passage 112, and the less extensivehead 152 at the proximal end of the spear 150 mates with the proximalend 114 of the sleeve 110. In this sense, the spear 150 and sleeve 110mate to form a solid type of plunger body with a length comparable tothe sleeve 110. Yet, when unmated, the spear 150 and sleeve 110 aresubject to different cross-sectional area to weight ratios that can bebeneficially configured for a given implementation.

Further alteration of the ratios can be achieved by altering thematerials used for the sleeve 110 and/or the spear 150. Although theabove examples show that increased length of one component (e.g., sleeve110) equates to a comparable increase in length of the other component(e.g., spear 150), this is not strictly necessary. It is possible inother configurations that the length of one component may bedisproportionate to the other component.

As previously depicted, landers 156 can be disposed on the head 152 ofthe spear 150 to stabilize the spear 150 when landed on the bumper (20).Further details of the landers 156 are shown in FIGS. 8A-8B. The landers156 can be protrusions, fins, tabs, or legs disposed about the head 152to help hold the spear 150 upright in the tubing (16) and mate with thesleeve 110.

As previously depicted, a fishneck profile 115 can be provided insidethe distal end of the sleeve 110. Further details of the fishneckprofile 115 are shown in FIG. 9. The fishneck profile 115 can allow thesleeve 110 to be retrieved using standard fishing techniques. The spear150 may need to be retrieved in other ways using a grabbing tool, forexample.

The sleeve 110 and spear 150 of the disclosed plunger 100 have beendepicted without seals. Use of a seal may be unnecessary for at leastpartially closing off fluid communication between the sleeve 110 and thespear 150 when mated together. However, it will be appreciated that oneor more seals may be used on the sleeve 110 and spear 150. For example,one or more seals can be used on the abutting surfaces between thesleeve's seat 118 and the spear's transition 138 so as not to interferewith the free decoupling between the sleeve 110 and spear 150.

The foregoing description of preferred and other embodiments is notintended to limit or restrict the scope or applicability of theinventive concepts conceived of by the Applicants. It will beappreciated with the benefit of the present disclosure that featuresdescribed above in accordance with any embodiment or aspect of thedisclosed subject matter can be utilized, either alone or incombination, with any other described feature, in any other embodimentor aspect of the disclosed subject matter.

In exchange for disclosing the inventive concepts contained herein, theApplicants desire all patent rights afforded by the appended claims.Therefore, it is intended that the appended claims include allmodifications and alterations to the full extent that they come withinthe scope of the following claims or the equivalents thereof.

What is claimed is:
 1. A plunger lift apparatus for tubing in a well,comprising: a sleeve for disposing in the tubing, the sleeve defining apassage therethrough from a first proximal end to a first distal end;and a spear for disposing in the tubing downhole of the sleeve, thespear being elongated and extending from a second proximal end to asecond distal end, the second distal end of the spear inserting in thepassage of the sleeve, the second proximal end of the spear mating withthe first proximal end of the sleeve, the spear at least partiallyclosing fluid communication through the passage of the sleeve when matedtherewith.
 2. The apparatus of claim 1, wherein the sleeve comprisesmeans for producing a pressure differential across the sleeve.
 3. Theapparatus of claim 1, wherein the sleeve and the spear mated togethermove uphole within the tubing by application of a pressure differential.4. The apparatus of claim 1, wherein the spear deploys at a faster ratedownhole in the tubing than the sleeve.
 5. The apparatus of claim 1,wherein the spear comprises a first weight greater than a second weightthan the sleeve.
 6. The apparatus of claim 1, wherein the spearcomprises a first cross-sectional area that is greater than a secondcross-sectional area of the sleeve.
 7. The apparatus of claim 1, whereinthe spear comprises a first axial length greater than a second axiallength of the sleeve.
 8. The apparatus of claim 7, wherein the seconddistal end of the spear extends beyond the first distal end of thesleeve and the second proximal end of the spear extends beyond the firstproximal end of the sleeve when the spear is mated with the sleeve. 9.The apparatus of claim 1, wherein the spear comprises a first ratio ofcross-sectional area to weight that is less than a second ratio ofcross-sectional area to weight of the sleeve.
 10. The apparatus of claim1, wherein the sleeve defines a seat in the passage toward the firstproximal end, the seat configured to engage a portion of the secondproximal end of the spear.
 11. The apparatus of claim 1, wherein thesecond proximal end of the spear comprises a head, and wherein thesecond distal end of the spear comprises a stem extending from the head.12. The apparatus of claim 11, wherein the head defines a bullet tip,and wherein the stem defines a sharpened end.
 13. The apparatus of claim11, wherein the head comprises one or more landers disposed thereon andstabilizing engagement of the spear downhole in the tubing.
 14. Theapparatus of claim 11, wherein the head comprises a first outerdimension being greater than a second outer dimension of the stem, aportion of the first outer dimension of the head being configured toengage a portion of the passage of the sleeve toward the first proximalend.
 15. The apparatus of claim 1, wherein the passage of the sleeve hasa first proximal opening toward the first proximal end and has a firstdistal opening toward the first distal end; wherein the second distalend of the spear installs through the first proximal opening; andwherein the second proximal end of the spear at least partially mates atthe first proximal opening of the passage.
 16. The apparatus of claim 1,further comprising a catcher disposed uphole of the tubing and operableto engage the sleeve.
 17. The apparatus of claim 16, further comprisinga controller operably coupled to the catcher and controlling engagementof the catcher with the sleeve.
 18. The apparatus of claim 1, furthercomprising: a valve in fluid communication with the tubing; and acontroller operably coupled to the valve and controlling the valve inresponse to a condition in the tubing.
 19. The apparatus of claim 1,wherein the second distal end of the spear is longer than the secondproximal end.
 20. A plunger lift apparatus for tubing in a well,comprising: a sleeve for disposing in the tubing, the sleeve defining apassage therethrough; and a spear for disposing in the tubing downholeof the sleeve, the spear mating with the sleeve downhole and at leastpartially closing fluid communication through the passage of the sleevewhen mated therewith, the spear deploying at a faster rate downhole inthe tubing than the sleeve.
 21. A plunger lift apparatus for tubing in awell, comprising: a sleeve for disposing in the tubing, the sleevedefining a passage therethrough and having a first ratio ofcross-sectional area to weight; and a spear for disposing in the tubingdownhole of the sleeve, the spear mating with the sleeve downhole and atleast partially closing fluid communication through the passage of thesleeve when mated therewith, the spear having a second ratio ofcross-sectional area to weight being less than the first ratio of thesleeve.
 22. The apparatus of claim 21, wherein the cross-sectional areacomprises an effective area responsible for force generated underdifferential pressure.
 23. A plunger lift method for tubing in a well,comprising: deploying a spear with a first ratio of cross-sectional areato weight downhole in the tubing; deploying a sleeve with a second ratioof cross-sectional area to weight downhole in the tubing separate to thespear by allowing fluid communication through a passage in the sleeve;preventing fluid communication through the passage in the sleeve byinserting a distal end of the spear in the passage and mating a proximalend of the spear with the passage; and lifting the mated sleeve andspear uphole in the tubing by application of a pressure differential.24. The method of claim 23, further comprising catching the sleevelifted uphole in the tubing.
 25. The method of claim 24, furthercomprising redeploying the sleeve downhole in the tubing by releasingthe sleeve manually or automatically.
 26. The method of claim 23,further comprising redeploying the spear downhole in the tubing byunmating the spear from the sleeve lifted uphole in the tubing.
 27. Themethod of claim 26, wherein redeploying the spear comprises permittingthe spear to deploy downhole in the tubing before permitting the sleeveto deploy downhole.
 28. The method of claim 23, wherein deploying thespear downhole in the tubing comprises permitting the spear to deploy ata faster rate downhole than the sleeve.
 29. The apparatus of claim 28,wherein permitting the spear to deploy at the faster rate downhole thanthe sleeve comprises providing the spear with one or more of: a firstweight greater than a second weight than the sleeve; a firstcross-sectional area that is greater than a second cross-sectional areaof the sleeve; a first axial length greater than a second axial lengthof the sleeve; and the first ratio of cross-sectional area to weightthat is less than the second ratio of cross-sectional area to weight ofthe sleeve.